The Hook-up and Commissioning program for the BP operated Clair Ridge facility was conducted over a period of three years, starting with the accommodation platform in 2015/16, and then the Production and drilling platform over 2017 and 2018. The total topsides weight is 53,000 tonnes, and the field is located in the harsh waters of the Atlantic West of Shetland. Typically 750 persons were based offshore, but over the life of the program some 7000 individuals worked offshore at some point on the project. Recognizing the safety leadership challenges with such a major hook-up and changing workforce a huge amount of effort went into preparation and working with our contractors to onboard the workforce. Over the first months of the campaign the safety metrics were healthy and there was a good reporting culture, however an increase in incidents was seen, including one late in 2015 where a medical evacuation was required from the platform. The individual made a full recovery and returned to work however it caused the Operator and Contractor project leaders to reflect on their safety leadership and how they were working with and engaging with the workforce. It was a catalyst for change as the team was determined that no other serious incidents would happen during the project delivery.
In this paper we will share the Clair Ridge safety leadership journey and the steps taken by the operator, with the support and collaboration of the main contractors, to set a new approach to safety through the development of a genuine Culture of Care. This included: Building of trust and credibility between leadership and the workforce Leadership openness and transparency in communication Empowering front-line supervision to be safety leaders and giving them the skills and tools to do this well
Building of trust and credibility between leadership and the workforce
Leadership openness and transparency in communication
Empowering front-line supervision to be safety leaders and giving them the skills and tools to do this well
As a result of the approach the Clair Ridge team is proud that, in the three years since the incident in 2015, over 9 million offshore workhours have been completed without any other Lost Time Incident, and a safe start-up was achieved with no process safety related incidents. Clair Ridge realised some of the highest participation in safety observations and near miss reporting across the Operator's global projects portfolio, a continual and significant reduction in all injuries and benefited from an excellent reporting culture.
A Culture of Care has been owned by all, and been recognised and commended by the contractor workforce and visitors to Clair Ridge.
BP and Chevron have overcome development challenges to recently launch production from two offshore projects that were years in the making. The British major said 23 November that oil is flowing from its giant Clair Ridge project in the West of Shetland region offshore UK. Two days earlier, San Ramon, California-based Chevron said that it started production from the deepwater Big Foot field in the US Gulf of Mexico. Clair Ridge, the larger of the two projects, is the second phase of development of the Clair field, targeting 640 million bbl of oil reserves with output expect to ramp up to a peak of 120,000 BOPD. BP’s £4.5-billion investment involved the construction of two new bridge-linked platforms along with oil and gas pipelines.
ConocoPhillips reportedly entered exclusive negotiations with Ineos for a possible sale of its UK North Sea assets, which could net $3 billion for the operator. The potential deal, first reported by the Sunday Times newspaper on 18 November and later confirmed by both companies, would be worth more than $3 billion. The assets up for sale will not include Conoco’s oil terminal in Teesside or its commercial trading group based in London. HSBC Holdings and Citigroup have been approached to provide financing. Ineos is the UK’s largest privately owned company, with sales of $60 billion and earnings before interest, tax, and other charges of $7 billion last year.
The Clair field is the largest discovered oilfield on the UK continental shelf (UKCS) but has high reservoir uncertainty associated with a complex natural fracture network. The field area covers over 200 sq km with an estimated STOIIP of 7 billion barrels. The scale and complexity of the reservoir has led to a phased multi-platform development.
Phase 1 started production in 2005 with 20 wells drilled prior to an extended drill break. Five new wells (A21 to A25) were drilled and brought online during 2016/17 which increased platform production by c.70%. The new wells incorporated historic lessons to mitigate the risk of wellbore instability in the overburden and be robust to the dynamic uncertainties of the fractured reservoir. Many of the well outcomes and risk events were predicted and mitigated effectively, however the new wells still provided some surprises.
This paper presents a summary of the lessons from the historic Clair development wells which underpinned the recent drilling campaign and additional field understanding provided by the new well results. New insights include a narrower overburden drilling window and zonal isolation challenges within the reservoir.
Reservoir connectivity over production timescales is a key uncertainty impacting estimated ultimate recover (EUR) per well, and ultimately the economics of a development, but is difficult to address without production data (particularly where the reservoir is poorly defined by seismic). While appraisal well tests can be designed to help predict the performance of future development wells, high rig costs in deepwater means the test duration is often insufficient to investigate the volume that would be accessed under production conditions. Recoverable resources from a recent deepwater gas discovery were dependent on demonstrating significant reservoir connectivity and net reservoir volume; however, this was complicated by a lower delta plain interval that was dominated by sub-seismic reservoir elements.
This paper describes the acquisition and interpretation of long-term pressure build-up data in a plugged and abandoned deepwater appraisal well. To accomplish the test objectives at an acceptable cost, we turned to a novel combination of well testing, wireless gauge technology and material balance techniques to allow the collection and interpretation of reservoir pressure data over a planned period of 6 to 15 months following the well test. The final build-up duration was 428 days (14 months).
Three interpretation methods of increasing complexity were used to provide insights into the reservoir. Firstly, material balance was used to produce an estimate of the minimum connected reservoir volume. The advantage of material balance is that it requires very few input assumptions and produces a high confidence result. Secondly, we used analytical models in commercial pressure transient analysis software to investigate near wellbore properties and distances to boundaries. Finally, we used finite difference simulation models to investigate reservoir properties and heterogeneity throughout the entire tested volume. With increasing model complexity came additional insights into the reservoir properties and architecture but reduced solution uniqueness.
A key complication for the interpretation of the recorded pressure data was the potential for gauge drift to occur – this was incorporated into the uncertainty range used in all three interpretation methods. The observed relative performance for the various gauges used during the well test is also reported in this paper.
Processing of Ocean Bottom Node (OBN), or any other marine acquisition type, surveys requires accurate knowledge of tidal height and acoustic water velocity variations. Pressure Inverted Echo Sounder (PIES) units are used in many OBN surveys to provide direct in field measurements to needed to compute tides and acoustic water velocity on a predetermined time interval. In order to determine these values accurately additional information is required, such as barometric pressure, depth dependent water pressure, temperature and conductivity. Combining the information from multiple field measurements allows for accurate determination of tide height and water velocity. Deep water and shallow water examples are used to illustrate the processing similarities and differences required due to proximity differences to the sea surface.
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: 204C (Anaheim Convention Center)
Presentation Type: Oral
Temizel, Cenk (Aera Energy) | Kirmaci, Harun (Consultant) | Tiwari, Aditya (Consultant) | Balaji, Karthik (University of Southern California) | Suhag, Anuj (University of Southern California) | Ranjith, Rahul (University of Southern California) | Wijaya, Zein (HESS) | Zhu, Ying (University of Southern California) | Yegin, Cengiz (Texas A&M University) | El Gazar, Ashraf Lofty (Abu Dhabi Co For Onshore Petroleum Operations Ltd.)
Condensate banking results from a combination of factors including fluid properties, formation flow characteristics, and pressures in the formation and wellbore. The production performance may suffer provided these factors are not understood at the beginning of field development. Determining the fluid properties can be vital in any reservoir, hence it plays a crucial role in gas-condensate reservoirs where condensate/gas ratio is significant in estimates for the sales potential of gas and liquid. Once reservoir fluids enter a wellbore both temperature and pressure conditions may change, where condensate liquid can be produced into the wellbore but liquid can also drop out within the wellbore. If the liquid falls back down the wellbore, the liquid percentage will increase and may eventually restrict the production. Thus, it is very important for robust reservoir management that each and every control and uncertainty parameter is understood not only in theory but also in practice with solid examples as done in this study.
A robust commercial optimization and uncertainty software is coupled with a full-physics commercial simulator that models the phenomenon so as to investigate the significance of major parameters on performance of gas-condensate reservoirs under recycling. Control and uncertainty variables have been investigated via several simulation runs in specified ranges to represent real reservoir and performance conditions rather than theoretical assumptions.
This study aims to prepare an insight into the mechanism of gas injection process in reducing gas-well productivity losses due to condensate blockage in the near wellbore region. The main goal of this work is to investigate gas recycling into the reservoir to enhance condensate recovery. The results show the influence of each control or uncertainty variable, leading to a better understanding of management of gas-condensate reservoirs under gas recycling. Impact of fractures is significant and the tornado diagrams illustrate the relative significance of each factor.
The results and sensitivities are compared and discussed in light of a comprehensive literature review of recycling gas-condensate reservoirs with different process optimization methods. The significance of all major parameters are outlined using tornado charts to serve as a practical example for optimization of relevant future applications.
Middle East Special Section
For nearly a decade, Saudi Aramco has been studying how altering the chemical makeup of seawater injected into its reservoirs can increase production. The result is an increasingly complex view of the interactions caused by the makeup of seawater that explains why seawater does more than just add pressure and help sweep the remaining oil out of a reservoir.
The goal is to cost-effectively maximize production by altering the chemistry of seawater. Hundreds of technical papers have been written on the potential benefits of reducing the salinity in seawater injected into formations.
More recently there has been a growing body of work on how other ingredients found in seawater—particularly sulfate, calcium, and magnesium—can add to oil output by freeing oil from reservoir rock.
Saudi Aramco has focused its research, dating back to 2008, on how seawater is able to increase production from carbonate reservoirs. Two recent technical papers from Saudi Aramco show that it has begun considering how it might modify its water treatment system to turn seawater into “smart water” (SPE 179564), and also offers an update on laboratory studies investigating how the active ingredients in seawater affect oil production (SPE 179590).
What is clear from those papers and other sources is that seawater, which Saudi Aramco turned to as a cheap option to scarce fresh water, can enhance the amount of oil ultimately recovered from the ground. The research also suggests that it can make seawater more effective by altering its chemical makeup, turning it into smart water. But this option is neither simple nor cheap.
Reducing the salinity of the extremely salty seawater used by Saudi Aramco would require desalination on a massive scale. Further changes to make it smart water add processing steps and may require new technology to reduce the energy required and to overcome the fact that available water treatment methods were not designed to selectively remove ingredients from water.Turning seawater into smart water is a logical next step for the company, which has long been processing seawater on a huge scale to maintain production from its fields. Its Al-Qurayyah Sea Water Plant processes millions of barrels a day of seawater, removing small particles, microorganisms, and oxygen. Now the company has begun considering whether to add further processing steps to apply what it has learned about seawater chemistry by fine-tuning the makeup of the water.
Caliper logs provide valuable information on the shape and wear of casing and tubing strings at various times throughout their operational life. In turn, this information is used to determine the remaining design strength. To clearly distinguish deformation and wear from deviations caused by manufacturing tolerance, the caliper measurements can be compared with a baseline log run soon after a tubular string has been run, or with surface-inspection data. However, a baseline log may not always be available. This paper addresses these situations and provides an assessment of the useful information that one can obtain. A mathematical model, based on the properties of the discrete Fourier transform, is presented to determine the caliper offset center and underlying tubular ovality from six or more equi-angularspaced caliper readings. The series-expansion approximation enables these parameters to be determined as a best fit from raw, uncentered data to a numerical accuracy of approximately 0.01% in a single pass. This is consistent with the accuracy and resolution of the currently available calipers. Complete numerical results from test cases based on exact geometric shapes, such as an offset circle and centered ellipse, plus field examples, are also included along with implementation notes. The same calculations can also be used to determine the underlying elliptic shape and orientation of an openhole caliper. In the casing specification API 5CT (2011), internal dimensions are indirectly described in relation to the unloaded casing or tubing outer diameter and wall thickness at surface conditions. The manufacturing tolerances and resulting uncertainties may be significant compared with the wear, but in some cases one can obtain useful information with corrections for downhole tension, temperature, and pressure effects. Details of these corrections and a discussion of other sensitivities are also provided. Such algorithms are usually considered by the service provider to be proprietary, and little quantitative material has been published on them or their interpretation. Also, data are often presented to the customer in only center-corrected form, which greatly restricts future reprocessing. This emphasizes the importance of acquiring and retaining the raw data.